Edgar Filing: CONCHO RESOURCES INC

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)


Delaware		76-0818600

(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

550 West Texas Avenue, Suite 100
Midland, Texas		79701

(Address of principal executive offices)		(Zip code)

(432) 683-7443

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Number of shares of the registrant’s common stock outstanding at May 6, 2009: 85,379,988 shares.

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION			iii

*Item 1.* Consolidated Financial Statements (Unaudited)			1

*Item 2.* Management’s Discussion and Analysis of Financial Condition and Results of Operations			35

*Item 3.* Quantitative and Qualitative Disclosures About Market Risk			48

*Item 4.* Controls and Procedures			50

PART II — OTHER INFORMATION			51

*Item 1.* Legal Proceedings			51

*Item 1A.* Risk Factors			51

*Item 2.* Unregistered Sales of Equity Securities and Use of Proceeds			51

*Item 6.* Exhibits			51
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This report may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed in our Annual Report on Form 10-K for the year ended December 31, 2008 could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Forward-looking statements may include statements about:

	•		our business and financial strategy;

	•		the estimated quantities of oil and natural gas reserves;

	•		our use of industry technology;

	•		our realized oil and natural gas prices;

	•		the timing and amount of the future production of our oil and natural gas;

	•		the amount, nature and timing of our capital expenditures;

	•		the drilling of our wells;

	•		our competition and government regulations;

	•		the marketing of our oil and natural gas;

	•		our exploitation activities or property acquisitions;

	•		the costs of exploiting and developing our properties and conducting other operations;

	•		general economic and business conditions;

	•		our cash flow and anticipated liquidity;

	•		uncertainty regarding our future operating results;

	•		our plans, objectives, expectations and intentions contained in this report that are not historical; and

	•		our ability to integrate acquisitions.

You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this report. We do not undertake any obligation to release publicly any revisions to any forward-looking statements to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events, except as required by law.

Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that they will be achieved. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

PART I — FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)


Consolidated Balance Sheets at March 31, 2009 and December 31, 2008			1

Consolidated Statements of Operations for the Three Months Ended March 31, 2009 and 2008			2

Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2009			3

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2009 and 2008			4

Condensed Notes to Consolidated Financial Statements			5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited


	March 31,			December 31,
(in thousands, except share and per share data)	2009			2008

Assets
Current assets:
Cash and cash equivalents	$	2,407		$	17,752
Accounts receivable, net of allowance for doubtful accounts:
Oil and natural gas		50,799			48,793
Joint operations and other		108,670			92,833
Related parties		260			314
Derivative instruments		86,082			113,149
Prepaid costs and other		4,361			5,942

Total current assets		252,579			278,783

Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		2,791,035			2,693,574
Accumulated depletion and depreciation		(357,585	)		(306,990	)

Total oil and natural gas properties, net		2,433,450			2,386,584
Other property and equipment, net		15,155			14,820

Total property and equipment, net		2,448,605			2,401,404

Deferred loan costs, net		14,845			15,701
Inventory		26,277			19,956
Intangible asset, net — operating rights		37,724			37,768
Noncurrent derivative instruments		48,649			61,157
Other assets		467			434

Total assets	$	2,829,146		$	2,815,203

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	22,082		$	7,462
Related parties		895			312
Other current liabilities:
Bank overdrafts		4,431			9,434
Revenue payable		24,559			22,286
Accrued and prepaid drilling costs		133,006			154,196
Derivative instruments		2,685			1,866
Deferred income taxes		26,504			37,205
Other current liabilities		36,343			38,057

Total current liabilities		250,505			270,818

Long-term debt		670,750			630,000
Noncurrent derivative instruments		1,777			—
Deferred income taxes		572,789			573,763
Asset retirement obligations and other long-term liabilities		16,662			15,468
Commitments and contingencies (Note K)
Stockholders’ equity:
Common stock, $0.001 par value; 300,000,000 authorized; 85,166,705 and 84,828,824 shares issued at March 31, 2009 and December 31, 2008, respectively		85			85
Additional paid-in capital		1,013,759			1,009,025
Retained earnings		302,944			316,169
Treasury stock, at cost; 3,142 shares at March 31, 2009 and December 31, 2008		(125	)		(125	)

Total stockholders’ equity		1,316,663			1,325,154

Total liabilities and stockholders’ equity	$	2,829,146		$	2,815,203

The accompanying notes are an integral part of these consolidated financial statements.

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited


	Three Months Ended March 31,
(in thousands, except per share amounts)	2009			2008

Operating revenues:
Oil sales	$	64,974		$	75,818
Natural gas sales		21,028			30,893

Total operating revenues		86,002			106,711

Operating costs and expenses:
Oil and natural gas production		24,766			16,895
Exploration and abandonments		5,995			2,741
Depreciation, depletion and amortization		50,748			21,284
Accretion of discount on asset retirement obligations		278			153
Impairments of long-lived assets		4,056			16
General and administrative (including non-cash stock-based compensation of $1,925 and $1,299 for the three months ended March 31, 2009 and 2008, respectively)		11,746			7,680
Ineffective portion of cash flow hedges		—			(564	)
Loss on derivatives not designated as hedges		5,046			17,178

Total operating costs and expenses		102,635			65,383

Income (loss) from operations		(16,633	)		41,328

Other income (expense):
Interest expense		(4,370	)		(5,615	)
Other, net		(328	)		1,020

Total other expense		(4,698	)		(4,595	)

Income (loss) before income taxes		(21,331	)		36,733
Income tax (expense) benefit		8,106			(14,368	)

Net income (loss)	$	(13,225	)	$	22,365

Basic earnings per share:
Net income (loss) per share	$	(0.16	)	$	0.30

Weighted average shares used in basic earnings per share		84,529			75,473

Diluted earnings per share:
Net income (loss) per share	$	(0.16	)	$	0.29

Weighted average shares used in diluted earnings per share		84,529			76,886

The accompanying notes are an integral part of these consolidated financial statements.

Concho Resources Inc.

Consolidated Statement of Stockholders’ Equity

Unaudited


						Additional										Total
	Common Stock					Paid-in		Retained			Treasury Stock					Stockholders’
(in thousands)	Shares			Amount		Capital		Earnings			Shares		Amount			Equity

BALANCE AT DECEMBER 31, 2008		84,829		$	85	$	1,009,025	$	316,169			3	$	(125	)	$	1,325,154
Net loss		—			—		—		(13,225	)		—		—			(13,225	)
Stock options exercised		248			—		2,005		—			—		—			2,005
Stock-based compensation for restricted stock		91			—		897		—			—		—			897
Cancellation of restricted stock		(1	)		—		—		—			—		—			—
Stock-based compensation for stock options		—			—		1,028		—			—		—			1,028
Excess tax benefits related to stock-based compensation		—			—		804		—			—		—			804

BALANCE AT MARCH 31, 2009		85,167		$	85	$	1,013,759	$	302,944			3	$	(125	)	$	1,316,663

The accompanying notes are an integral part of these consolidated financial statements.

Concho Resources Inc.

Consolidated Statements of Cash Flows
Unaudited


	Three Months Ended March 31,
(in thousands)	2009			2008

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(13,225	)	$	22,365
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		50,748			21,284
Impairments of long-lived assets		4,056			16
Accretion of discount on asset retirement obligations		278			153
Exploration expense, including dry holes		5,318			848
Non-cash compensation expense		1,925			1,299
Deferred income taxes		(10,871	)		14,368
(Gain) loss on sale of assets		243			(777	)
Ineffective portion of cash flow hedges		—			(564	)
Loss on derivatives not designated as hedges		5,046			17,178
Dedesignated cash flow hedges reclassified from accumulated other comprehensive income		—			296
Other non-cash items		813			334
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		(31,744	)		(281	)
Prepaid costs and other		1,581			1,849
Inventory		(2,371	)		(152	)
Accounts payable		15,203			(11,619	)
Revenue payable		2,273			3,362
Other current liabilities		11,339			(154	)

Net cash provided by operating activities		40,612			69,805

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on oil and natural gas properties		(131,559	)		(51,537	)
Additions to other property and equipment		(1,078	)		(2,803	)
Proceeds from the sale of oil and natural gas properties and other assets		1,000			1,034
Settlements received (paid) on derivatives not designated as hedges		37,124			(3,987	)

Net cash used in investing activities		(94,513	)		(57,293	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		100,650			—
Payments of long-term debt		(59,900	)		(26,500	)
Exercise of stock options		2,005			1,238
Excess tax benefit from stock-based compensation		804			593
Proceeds from repayment of officer and employee notes		—			333
Bank overdrafts		(5,003	)		(2,908	)

Net cash provided by (used in) financing activities		38,556			(27,244	)

Net decrease in cash and cash equivalents		(15,345	)		(14,732	)
Cash and cash equivalents at beginning of period		17,752			30,424

Cash and cash equivalents at end of period	$	2,407		$	15,692

SUPPLEMENTAL CASH FLOWS:
Cash paid for interest and fees, net of $15 and $475 capitalized interest	$	3,457		$	6,301
Cash paid for income taxes	$	1,065		$	—

The accompanying notes are an integral part of these consolidated financial statements.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2009

Unaudited

Note A. Organization and nature of operations

Concho Resources Inc. (the “Company”) is a Delaware corporation formed on February 22, 2006. The Company’s principal business is the acquisition, development, exploitation and exploration of oil and natural gas properties in the Permian Basin region of Southeastern New Mexico and West Texas.

Note B. Summary of significant accounting policies

Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its wholly-owned subsidiaries. All material intercompany balances and transactions have been eliminated.

Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of derivative financial instruments, purchase price allocations for business and oil and natural gas property acquisitions and fair value of stock-based compensation.

Interim financial statements. The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2008 is derived from audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present fairly the Company’s financial position at March 31, 2009, its results of operations and its cash flows for the three months ended March 31, 2009 and 2008. All such adjustments are of a normal recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed or omitted from these consolidated financial statements. Accordingly, these consolidated financial statements should be read with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.

Deferred loan costs. Deferred loan costs are stated at cost, net of amortization, which is computed using the effective interest and straight-line methods. The Company had deferred loan costs of $14.8 million and $15.7 million, net of accumulated amortization of $4.2 million and $3.3 million, at March 31, 2009 and December 31, 2008, respectively.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

Future amortization expense of deferred loan costs at March 31, 2009 is as follows:


(in thousands)	Total

Remaining 2009	$	2,570
2010		3,426
2011		3,426
2012		3,426
2013		1,997

Total	$	14,845

Intangible assets. The Company has capitalized certain operating rights acquired in an acquisition, see Note D. The gross operating rights of approximately $38.8 million, which have no residual value, are amortized over the estimated economic life of approximately 25 years. Impairment will be assessed if indicators of potential impairment exist or when there is a material change in the remaining useful economic life. Amortization expense for the three months ended March 31, 2009 was approximately $0.4 million. The following table reflects the estimated aggregate amortization expense for each of the periods presented below:


(in thousands)

Remaining 2009	$	1,163
2010		1,550
2011		1,550
2012		1,550
2013		1,550
Thereafter		30,361

Total	$	37,724

Oil and natural gas sales and imbalances. Oil and natural gas revenues are recorded at the time of delivery of such products to pipelines for the account of the purchaser or at the time of physical transfer of such products to the purchaser. The Company follows the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s share of actual proceeds from the oil and natural gas sold to purchasers. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. Imbalances are tracked by well, but the Company does not record any receivable from or payable to the other owners unless the imbalance has reached a level at which it exceeds the remaining reserves in the respective well. If reserves are insufficient to offset the imbalance and the Company is in an overtake position, a liability is recorded for the amount of shortfall in reserves valued at a contract price or the market price in effect at the time the imbalance is generated. If the Company is in an undertake position, a receivable is recorded for an amount that is reasonably expected to be received, not to exceed the current market value of such imbalance.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

The following table reflects the Company’s natural gas imbalance positions at March 31, 2009 and December 31, 2008 as well as amounts reflected in oil and natural gas production expense for the three months ended March 31, 2009 and 2008:


	March 31,		December 31,
(dollars in thousands)	2009		2008

Natural gas imbalance liability (included in asset retirement obligations and other long-term liabilities)	$	455	$	472
Overtake position (Mcf)		81,189		85,698

Natural gas imbalance receivable (included in other assets)	$	439	$	406
Undertake position (Mcf)		97,578		90,321


	Three Months Ended March 31,
	2009		2008

Value of net undertake arising during the period (reducing oil and natural gas production expense)	$	49	$	4
Net undertake position arising during the period (Mcf)		11,766		1,014

Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.

General and administrative expense. The Company receives fees for the operation of jointly owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $2.7 million and $0.2 million for the three months ended March 31, 2009 and 2008, respectively.

Reclassifications. Certain prior period amounts have been reclassified to conform to the 2009 presentation. These reclassifications had no impact on net income (loss), total stockholders’ equity or cash flows.

Recent accounting pronouncements. In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS No. 141(R)”), which replaces FASB Statement No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. The Company adopted SFAS No. 141(R) effective January 1, 2009. There has been no impact on the Company’s consolidated financial statements, as it has not entered into any business combinations in 2009.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51. SFAS No. 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Company adopted SFAS No. 160 effective January 1, 2009, with no impact on the Company’s consolidated financial statements.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

161 effective January 1, 2009, with no significant impact on the Company’s consolidated financial statements, other than additional disclosures which are set forth below in Note H.

In April 2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, Determination of the Useful Life of Intangible Assets (“FSP SFAS No. 142-3”). FSP SFAS No. 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”). The intent of FSP SFAS No. 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R and other applicable accounting literature. FSP SFAS No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date. The Company adopted FSP SFAS No. 142-3 effective January 1, 2009, with no significant impact on the Company’s consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (“GAAP”) in the United States of America. This statement became effective for the Company on November 15, 2008. The adoption of SFAS No. 162 did not have a significant impact on the Company’s consolidated financial statements.

In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, (“FSP EITF 03-6-1”) which provides that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share under the two class method. FSP EITF 03-6-1 was effective for the Company on January 1, 2009. There was no impact on the Company’s consolidated financial statements.

In April 2009, the FASB issued FSP SFAS No. 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies. This FSP amends and clarifies SFAS No. 141(R) to address application issues raised by preparers, auditors, and members of the legal profession on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company has not made any acquisitions during the first quarter of 2009, and as such, the adoption of this statement did not have a significant impact.

In April 2009, the FASB issued FSP SFAS No. 107-1 and APB Opinion No. 28-1, Interim Disclosures about Fair Value of Financial Instrument (“FSP SFAS No. 107-1”). This FSP amends FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods. This FSP is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. An entity may early adopt this FSP only if it also elects to early adopt FSP SFAS No. 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, (“FSP SFAS No. 157-4”) and FSP SFAS No. 115-2 and SFAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments. The Company did not elect early adoption. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this FSP requires comparative disclosures only for periods ending after initial adoption. The Company is currently evaluating the potential impact, if any, of FSP SFAS No. 107-1 on its financial statement disclosures.

In April 2009, the FASB issued FSP SFAS No. 157-4. This FSP:

•

Affirms that the objective of fair value when the market for an asset is not active is the price that would be received to sell the asset in an orderly transaction.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

	•		Clarifies and includes additional factors for determining whether there has been a significant decrease in market activity for an asset when the market for that asset is not active.

	•		Eliminates the proposed presumption that all transactions are distressed (not orderly) unless proven otherwise. The FSP instead requires an entity to base its conclusion about whether a transaction was not orderly on the weight of the evidence.

	•		Includes an example that provides additional explanation on estimating fair value when the market activity for an asset has declined significantly.

	•		Requires an entity to disclose a change in valuation technique (and the related inputs) resulting from the application of the FSP and to quantify its effects, if practicable.

	•		Applies to all fair value measurements when appropriate.

FSP SFAS No. 157-4 must be applied prospectively and retrospective application is not permitted. FSP SFAS No. 157-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. An entity early adopting FSP SFAS No. 157-4 must also early adopt FSP SFAS No. 115-2 and SFAS No. 124-2. The Company is not affected by FSP SFAS No. 115-2 and SFAS No. 124-2. The Company is currently evaluating the potential impact, if any, of FSP SFAS No. 157-4 on its financial statements.

Recent developments in reserves reporting. In December 2008, the United States Securities and Exchange Commission (the “SEC”) released Final Rule, Modernization of Oil and Gas Reporting, (the “Reserve Ruling”). The Reserve Ruling revises oil and gas reporting disclosures. The Reserve Ruling also permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The Reserve Ruling will also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The Reserve Ruling becomes effective for fiscal years ending on or after December 31, 2009. The Company is currently assessing the impact that adoption of the provisions of the Reserve Ruling will have on its financial position, results of operations and disclosures.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

Note C. Exploratory well costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are presented in unproved properties in the Consolidated Balance Sheets. If the exploratory well is determined to be impaired, the well costs are charged to expense.

The following table reflects the Company’s capitalized exploratory well activity during the three months ended March 31, 2009:


	Three Months Ended
(in thousands)	March 31, 2009

Beginning capitalized exploratory well costs		$	25,553
Additions to exploratory well costs pending the determination of proved reserves			2,537
Reclassifications due to determination of proved reserves			(25,103	)
Exploratory well costs charged to expense			(451	)

Ending capitalized exploratory well costs		$	2,536

The following table provides an aging, at March 31, 2009 and December 31, 2008, of capitalized exploratory well costs based on the date drilling was completed:


	March 31,		December 31,
(in thousands)	2009		2008

Wells in drilling progress	$	—	$	7,765
Capitalized exploratory well costs that have been capitalized for a period of one year or less		2,536		17,788
Capitalized exploratory well costs that have been capitalized for a period greater than one year		—		—

Total capitalized exploratory well costs	$	2,536	$	25,553

At March 31, 2009, the Company had five gross exploratory wells waiting on their completion, including three wells in the Texas Permian area, one well in the New Mexico Permian area and one well in the Williston Basin of North Dakota.

Note D. Acquisitions

Henry Entities acquisition. On July 31, 2008, the Company closed the acquisition of Henry Petroleum LP and certain entities affiliated with Henry Petroleum LP (referred to as “Henry” or the “Henry Entities”) and additional non-operated interests in oil and natural gas properties from persons affiliated with the Henry Entities. In August 2008 and September 2008, the Company acquired additional non-operated interests in oil and natural gas properties from persons affiliated with the Henry Entities. The assets acquired in the Henry Entities acquisition, including the additional non-operated interests, are referred to as the “Henry Properties.” The Company paid $584.1 million in cash for the Henry Properties acquisition.

The cash paid for the Henry Properties acquisition was funded with (i) borrowings under the Company’s credit facility and (ii) proceeds from a private placement of approximately 8.3 million shares of the Company’s common stock.

The Henry Properties acquisition is being accounted for using the purchase method of accounting for business combinations. Under the purchase method of accounting, the Company recorded the Henry Properties’ assets and liabilities at fair value. The purchase price of the acquired Henry Properties’ net assets is based on the total value of the cash consideration. The initial purchase

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

price allocation is preliminary and subject to adjustment primarily due to resolution of certain tax matters. Any future adjustments to the allocation of the total purchase price are not anticipated to be material to the Company’s consolidated financial statements.

The following tables represent the preliminary allocation of the total purchase price of the Henry Properties to the acquired assets and liabilities of the Henry Properties and the consideration paid for the Henry Properties. The allocation represents the fair values assigned to each of the assets acquired and liabilities assumed:


(in thousands)

Fair value of Henry Properties’ net assets:
Current assets, net of cash acquired of $19,049 ^(a)	$	86,321
Proved oil and natural gas properties		594,065
Unproved oil and natural gas properties		233,790
Other long-term assets		6,977
Intangible assets — operating rights		38,758

Total assets acquired		959,911

Current liabilities		(113,729	)
Asset retirement obligations and other long-term liabilities		(7,529	)
Noncurrent derivative liabilities		(39,037	)
Deferred tax liability		(215,475	)

Total liabilities assumed		(375,770	)

Net purchase price	$	584,141


Consideration paid for Henry Properties’ net assets:
Cash consideration paid, net of cash acquired of $19,049	$	578,491
Acquisition costs ^(b)		5,650

Total purchase price	$	584,141


(a)		Includes a deferred tax asset of approximately $9.0 million.

(b)		Estimated acquisition costs include legal and accounting fees, advisory fees and other acquisition-related costs.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

The following unaudited pro forma combined condensed financial data for the three months ended March 31, 2008 was derived from the historical financial statements of the Company and Henry Properties giving effect to the acquisition as if it had occurred on January 1, 2008. The unaudited pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Henry Properties acquisition taken place as of the date indicated and is not intended to be a projection of future results.


	Three Months Ended
(in thousands, except per share data)	March 31, 2008

Operating revenues	$	154,424
Net income	$	14,542
Earnings per common share:
Basic	$	0.17
Diluted	$	0.17

Note E. Asset retirement obligations

The Company’s asset retirement obligations represent the estimated present value of the estimated cash flows the Company will incur to plug, abandon and remediate its producing properties at the end of their production lives, in accordance with applicable state laws. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.

The following table summarizes the Company’s asset retirement obligation (“ARO”) transactions recorded during the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
(in thousands)	2009			2008

Asset retirement obligations, beginning of period	$	16,809		$	9,418
Liabilities incurred from new wells		168			34
Accretion expense		278			153
Disposition of wells sold		(142	)		—
Liabilities settled upon plugging and abandoning wells		(10	)		—
Revision of estimates		1,151			(810	)


Asset retirement obligations, end of period	$	18,254		$	8,795

Note F. Stockholders’ equity

Common stock private placement. On June 5, 2008, the Company entered into a common stock purchase agreement with certain unaffiliated third-party investors to sell certain shares of the Company’s common stock in a private placement (the “Private Placement”) contemporaneous with the closing of the Henry Properties acquisition. On July 31, 2008, the Company issued 8,302,894 shares of its common stock at $30.11 per share. The Private Placement resulted in net proceeds of approximately $242.4 million to the Company, after payment of approximately $7.6 million for the fee paid to the placement agent.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

In connection with the Private Placement, the Company entered into a registration rights agreement with the investors. On October 24, 2008, pursuant to the registration rights agreement, the Company filed a registration statement to register the shares of common stock issued in the Private Placement.

Treasury stock. On June 12, 2008, the restrictions on certain restricted stock awards issued to five of the Company’s executive officers lapsed. Immediately upon the lapse of restrictions, these executive officers became liable for certain federal income taxes on the value of such shares. In accordance with the Company’s 2006 Stock Incentive Plan and the applicable restricted stock award agreements, four of such officers elected to deliver shares of the Company’s common stock to the Company to satisfy such tax liability, and the Company acquired 3,142 shares to be held as treasury stock in the approximate amount of $125,000.

Note G. Incentive plans

Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees and maintains certain other acquired plans. The Company matches 100 percent of employee contributions, not to exceed 6 percent of the employee’s annual salary. The Company contributions to the plans for the three months ended March 31, 2009 and 2008 were approximately $0.3 million and $0.1 million, respectively.

Stock incentive plan. The Company’s 2006 Stock Incentive Plan (together with applicable option agreements and restricted stock agreements, the “Plan”) provides for granting stock options and restricted stock awards to employees and individuals associated with the Company. The following table shows the number of awards available under the Company’s Plan at March 31, 2009:


	Number of
	Common Shares

Approved and authorized awards		5,850,000
Stock option grants, net of forfeitures		(3,461,485	)
Restricted stock grants, net of forfeitures		(602,334	)

Awards available for future grant		1,786,181

Restricted stock awards. All restricted shares are treated as issued and outstanding in the accompanying consolidated balance sheets. If an employee terminates employment prior to the lapse date, the awarded shares are forfeited and cancelled and are no longer considered issued and outstanding. A summary of the Company’s restricted stock awards activity for the three months ended March 31, 2009 is presented below:


	Number of			Grant Date
	Restricted			Fair Value
	Shares			Per Share

Outstanding at December 31, 2008		407,351
Shares granted		90,688		$	20.40
Shares cancelled / forfeited		(1,163	)
Lapse of restrictions		(12,500	)

Outstanding at March 31, 2009		484,376

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

A summary of the impact on the consolidated statements of operations for the Company’s restricted stock awards during the three months ended March 31, 2009 and 2008 is presented below:


	Three Months Ended March 31,
(in thousands)	2009		2008

Stock-based compensation expense related to restricted stock	$	897	$	394
Income tax benefit related to restricted stock	$	341	$	154
Deductions in current taxable income related to restricted stock	$	378	$	—

Stock option awards. A summary of the Company’s stock option awards activity under the Plan for the three months ended March 31, 2009 is presented below:


				Weighted
				Average
	Number of			Exercise
	Options			Price

Outstanding at December 31, 2008		2,731,324		$	12.46
Options granted		117,801		$	20.40
Options exercised		(248,356	)	$	8.08

Outstanding at March 31, 2009		2,600,769		$	13.24


Vested at end of period		1,747,913		$	9.89


Vested and exercisable at end of period		922,921		$	11.42

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

The following table summarizes information about the Company’s vested and exercisable stock options outstanding at March 31, 2009:


					Weighted
					Average	Weighted
			Number of		Remaining	Average
			Stock		Contractual	Exercise		Intrinsic
			Options		Life	Price		Value
								(in thousands)
*Vested options:*

March 31, 2009:
Exercise price	$	8.00		1,311,633	2.68 years	$	8.00	$	23,072
Exercise price	$	12.00		138,780	4.86 years	$	12.00		1,886
Exercise price	$	14.68		191,250	7.54 years	$	14.68		2,086
Exercise price	$	21.84		106,250	8.91 years	$	21.84		399

				1,747,913		$	9.89	$	27,443


*Vested and exercisable options:*

March 31, 2009:
Exercise price	$	8.00		522,602	3.34 years	$	8.00	$	9,193
Exercise price	$	12.00		102,819	5.77 years	$	12.00		1,397
Exercise price	$	14.68		191,250	7.54 years	$	14.68		2,086
Exercise price	$	21.84		106,250	8.91 years	$	21.84		399

				922,921		$	11.42	$	13,075

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

The following table summarizes information about stock-based compensation for stock options for the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
(in thousands)	2009		2008

*Grant date fair value for awards during the period:*

Time vesting options	$	—	$	183
Stock option grants under the Plan	1,454		4,296
Total	$	1,454	$	4,479


*Stock-based compensation expense from stock options:*

Time vesting options	$	71	$	30
Performance vesting options:
Officers		71		150
Stock option grants under the Plan		886		725

Total	$	1,028	$	905


*Income taxes and other information:*

Income tax benefit related to stock options	$	391	$	354
Deductions in current taxable income related to stock options exercised	$	3,040	$	—

In calculating compensation expense for options granted during the three months ended March 31, 2009, the Company has estimated the fair value of each grant using the Black-Scholes option-pricing model. Assumptions utilized in the model are shown below:


Risk-free interest rate	2.46	%
Expected term (years)	6.25
Expected volatility	63.40	%
Expected dividend yield	—

As permitted by Staff Accounting Bulletin No. 110, Share-Based Payment, the Company used the simplified method to calculate the expected term for stock options granted during the three months ended March 31, 2009, since it does not have sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term due to the limited period of time its shares of common stock have been publicly traded. Expected volatilities are based on a combination of historical and implied volatilities of comparable companies.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

Future stock-based compensation expense. Future stock-based compensation expense at March 31, 2009 is summarized in the table below:


	Restricted		Stock
(in thousands)	Stock		Options		Total

Remaining 2009	$	2,568	$	2,309	$	4,877
2010		1,895		1,694		3,589
2011		699		706		1,405
2012		143		166		309
2013		14		14		28

Total	$	5,319	$	4,889	$	10,208

Note H. Disclosures about fair value of financial instruments

The Company adopted SFAS No. 157, Fair Value Measurements, (“SFAS No. 157”) effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. In February 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 by one year for nonfinancial assets and liabilities. As of January 1, 2009, the Company adopted the provisions of SFAS 157 related to our nonfinancial assets and liabilities, including nonfinancial assets and liabilities measured at fair value in a business combination; impaired long-lived assets; and initial recognition of asset retirement obligations. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:


		*Level 1*:		Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

		*Level 2*:		Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company utilizes our counterparties’ valuations to assess the reasonableness of our prices and valuation techniques.

		*Level 3*:		Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Level 3 instruments primarily include derivative instruments, such as commodity price collars and floors, as well as investments. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although the Company utilizes our counterparties’ valuations to assess the reasonableness of our prices and valuation techniques, the Company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

The following represents information about the estimated fair values of the Company’s financial instruments:

Cash and cash equivalents, accounts receivable, other current assets, accounts payable, interest payable and other current liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.

Line of credit and term note. The carrying amount of borrowings outstanding under the Company’s credit facility approximate fair value because the instruments bear interest at variable market rates.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Derivative instruments. The fair value of the derivative instruments are estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. As required by SFAS No. 157, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table (i) summarizes the valuation of each of the Company’s financial instruments by SFAS No. 157 pricing levels and (ii) summarizes the gross fair value by the appropriate balance sheet classification, in accordance with SFAS No. 161, even when the derivative instruments are subject to master netting arrangements and qualify for net presentation in the consolidated balance sheets at March 31, 2009 and December 31, 2008:


	Fair value measurements using
	Quoted		Significant						Total
	prices		other			Significant			carrying value
	in active		observable			unobservable			at
	markets		inputs			inputs			March 31,
(in thousands)	(Level 1)		(Level 2)			(Level 3)			2009

Assets ⁽¹⁾
Current:^(a)
Commodity derivative price swap contracts	$	—	$	56,316		$	—		$	56,316
Commodity derivative basis swap contracts		—		—			—			—
Interest rate derivative swap contracts		—		—			—			—
Commodity derivative price collar contracts		—		—			36,870			36,870

		—		56,316			36,870			93,186

Noncurrent:^(b)
Commodity derivative price swap contracts		—		58,773			—			58,773
Commodity derivative basis swap contracts		—		—			—			—
Interest rate derivative swap contracts		—		—			—			—
Commodity derivative price collar contracts		—		—			—			—

		—		58,773			—			58,773

Liabilities ⁽¹⁾
Current:^(a)
Commodity derivative price swap contracts		—		(4,281	)		—			(4,281	)
Commodity derivative basis swap contracts		—		(1,007	)		—			(1,007	)
Interest rate derivative swap contracts		—		(3,072	)		—			(3,072	)
Commodity derivative price collar contracts		—		—			(1,429	)		(1,429	)

		—		(8,360	)		(1,429	)		(9,789	)

Noncurrent:^(b)
Commodity derivative price swap contracts		—		(9,198	)		—			(9,198	)
Commodity derivative basis swap contracts		—		(569	)		—			(569	)
Interest rate derivative swap contracts		—		(437	)		—			(437	)
Commodity derivative price collar contracts		—		—			(1,697	)		(1,697	)

		—		(10,204	)		(1,697	)		(11,901	)

Total financial assets (liabilities)	$	—	$	96,525		$	33,744		$	130,269


(a) Total current financial assets (liabilities), gross basis	$	83,397
(b) Total noncurrent financial assets (liabilities), gross basis		46,872

Total financial assets (liabilities)	$	130,269

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited


	Fair value measurements using
	Quoted		Significant					Total
	prices		other			Significant		carrying value
	in active		observable			unobservable		at
	markets		inputs			inputs		December 31,
(in thousands)	(Level 1)		(Level 2)			(Level 3)		2008

Assets ⁽¹⁾
Current:^(a)
Commodity derivative price swap contracts	$	—	$	64,162		$	—	$	64,162
Commodity derivative basis swap contracts		—		—			—		—
Interest rate derivative swap contracts		—		—			—		—
Commodity derivative price collar contracts		—		—			49,562		49,562

		—		64,162			49,562		113,724

Noncurrent:^(b)
Commodity derivative price swap contracts		—		60,995			—		60,995
Commodity derivative basis swap contracts		—		—			—		—
Interest rate derivative swap contracts		—		678			—		678
Commodity derivative price collar contracts		—		—			—		—

		—		61,673			—		61,673

Liabilities ⁽¹⁾
Current:^(a)
Commodity derivative price swap contracts		—		—			—		—
Commodity derivative basis swap contracts		—		(680	)		—		(680	)
Interest rate derivative swap contracts		—		(1,761	)		—		(1,761	)
Commodity derivative price collar contracts		—		—			—		—

		—		(2,441	)		—		(2,441	)

Noncurrent:^(b)
Commodity derivative price swap contracts		—		(516	)		—		(516	)
Commodity derivative basis swap contracts		—		—			—		—
Interest rate derivative swap contracts		—		—			—		—
Commodity derivative price collar contracts		—		—			—		—

		—		(516	)		—		(516	)

Total financial assets (liabilities)	$	—	$	122,878		$	49,562	$	172,440


(a) Total current financial assets (liabilities), gross basis	$	111,283
(b) Total noncurrent financial assets (liabilities), gross basis		61,157

Total financial assets (liabilities)	$	172,440

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited


(1)		The fair value of derivative instruments reported in the consolidated balance sheets are subject to master netting arrangements and qualify for net presentation. The following table reports the net basis derivative fair values as reported in the consolidated balance sheets at March 31, 2009 and December 31, 2008:


	March 31,			December 31,
	2009			2008
Consolidated Balance Sheet Classification:

Current derivative contracts:

Assets	$	86,082		$	113,149
Liabilities		(2,685	)		(1,866	)

Net current	$	83,397		$	111,283


Noncurrent derivative contracts:

Assets	$	48,649		$	61,157
Liabilities		(1,777	)		—

Net noncurrent	$	46,872		$	61,157

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:


(in thousands)
\|
Balance at January 1, 2009	$	49,562
Realized and unrealized gains		(1,056	)
Purchases, issuances, and settlements		(14,762	)

Balance at March 31, 2009	$	33,744


Total losses for the period included in earnings attributable to the change in unrealized losses relating to assets still held at the reporting date	$	(15,818	)

For additional information on the Company’s derivative instruments see Note I.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Impairments of long-lived assets — In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company reviews its long-lived assets to be held and used, including proved oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and gas properties by amortization base or by individual well for those wells not constituting part of an amortization base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and unproved oil and gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

As a result of a significant decline in the assumptions at March 31, 2009, the Company reviewed its proved oil and gas properties that are sensitive to oil and natural gas prices for impairment. The Company recognized impairment expense of $4.1 million for the three months ended March 31, 2009, related to its proved oil and gas properties. The impaired assets, which had a total carrying amount of $6.9 million, were reduced to their estimated fair value of $2.8 million.

Asset Retirement Obligations — The Company estimates the fair values of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note E for a summary of changes in AROs.

Measurement information for assets that are measured at fair value on a nonrecurring basis was as follows:


	Fair value measurements using
	Quoted		Significant
	prices		other		Significant
	in active		observable		unobservable		Total
	markets		inputs		inputs		Impairment
(in thousands)	(Level 1)		(Level 2)		(Level 3)		Loss

Three months ended March 31, 2009:
Impairment of long-lived assets	$	—	$	—	$	2,887	$	(4,056	)
Asset retirement obligations incurred in current period		—		—		168

Three months ended March 31, 2008:
Impairment of long-lived assets	$	—	$	—	$	—	$	(16	)
Asset retirement obligations incurred in current period		—		—		34

Note I. Derivative financial instruments

The Company uses derivative financial contracts to manage exposures to commodity price and interest rate fluctuations. Commodity hedges are used to (i) reduce the effect of the volatility of price changes on the natural gas and oil the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. Interest rate hedges are used to mitigate the cash flow risk associated with rising interest rates. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company also may enter into physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the financial statements.

Currently, the Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects the changes in the fair value of its derivative instruments in the statements of operations. All of the Company’s remaining hedges that historically qualified for hedge accounting or were dedesignated from hedge accounting were settled in 2008.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

New commodity derivatives contracts in 2009. During the three months ended March 31, 2009, the Company entered into additional commodity derivative contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts:

Aggregate

Daily

Index

Contract

Volume

Price

Period

Oil (volumes in Bbls):

Price swap

540,000

2,935

$51.62 ^(a)

7/1/09 - 12/31/09

Price swap

1,608,000

4,405

$55.83 ^(a)

1/1/10 - 12/31/10

Price collar

600,000

6,522

$45.00 - $49.00^{(a) (e)}

3/1/09 - 5/31/09

Natural gas (volumes in MMBtus):

Price swap

3,000,000

16,393

$4.31 ^(b)

4/1/09 - 9/30/09

Price collar

9,000,000

16,453

$5.42 - $6.12^{(c) (e)}

10/1/09 - 3/31/11

Basis swap

7,500,000

16,484

$0.90 ^(d)

1/1/10 - 3/31/11


(a)		The index prices for the oil price swaps and collars are based on the NYMEX-West Texas Intermediate monthly average futures price.

(b)		The index price for the natural gas price swap is based on the NYMEX-Henry Hub last trading day futures price.

(c)		The index price for the natural gas price collar is based on the NYMEX-Henry Hub last trading day futures price.

(d)		The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery point.

(e)		Prices represent weighted average prices.

On May 5, 2009, the Company entered into an oil price swap to hedge an additional portion of its estimated oil production for 2011 at a price of $70.15 per Bbl.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

Commodity derivative contracts at March 31, 2009. The following table sets forth the Company’s outstanding commodity derivative contracts at March 31, 2009:


	First		Second			Third		Fourth
	Quarter		Quarter			Quarter		Quarter		Total

Oil Swaps:
*2009:*
Volume (Bbl)				452,673			725,473		725,473		1,903,619
Price per Bbl ^{(a) (f)}			$	87.17		$	73.91	$	73.91	$	77.06
*2010:*
Volume (Bbl)		562,436		562,436			562,436		562,436		2,249,744
Price per Bbl ^(a)	$	66.50	$	66.50		$	66.50	$	66.50	$	66.50
*2011:*
Volume (Bbl)		139,436		139,436			139,436		139,436		557,744
Price per Bbl ^{(a) (f)}	$	104.91	$	104.91		$	104.91	$	104.91	$	104.91
*2012:*
Volume (Bbl)		126,000		126,000			126,000		126,000		504,000
Price per Bbl ^(a)	$	127.80	$	127.80		$	127.80	$	127.80	$	127.80

Oil Collars:
*2009:*
Volume (Bbl)				592,000			192,000		192,000		976,000
Price per Bbl ^(a)			$	69.32 - $76.76	^(f)	$	120.00 - $134.60	$	120.00 - $134.60	$	89.26 - $99.52	^(f)

Natural Gas Swaps:
*2009:*
Volume (MMBtu)				455,000			460,000		460,000		1,375,000
Price per MMBtu ^(b)			$	8.44		$	8.44	$	8.44	$	8.44
*2009:*
Volume (MMBtu)		—		1,500,000			1,500,000		—		3,000,000
Price per MMBtu ^(c)		—	$	4.31		$	4.31		—	$	4.31

Natural Gas Collars:
*2009:*
Volume (MMBtu)				—			—		1,500,000		1,500,000
Price per MMBtu ^(d)				—			—	$	5.00 - $5.81	$	5.00 - $5.81
*2010:*
Volume (MMBtu)		1,500,000		1,500,000			1,500,000		1,500,000		6,000,000
Price per MMBtu ^(d)	$	5.00 - $5.81	$	5.25 - $5.75		$	5.25 - $5.75	$	6.00 - $6.80	$	5.38 - $6.03	^(f)
*2011:*
Volume (MMBtu)		1,500,000		—			—		—		1,500,000
Price per MMBtu ^(d)	$	6.00 - $6.80		—			—		—	$	6.00 - $6.80

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total

Natural Gas Basis Swaps:
*2009:*
Volume (MMBtu)				1,501,500		1,518,000		1,518,000		4,537,500
Price per MMBtu ^{(e) (f)}			$	1.08	$	1.08	$	1.08	$	1.08
*2010:*
Volume (MMBtu)		1,500,000		1,500,000		1,500,000		1,500,000		6,000,000
Price per MMBtu ^(e)	$	0.90	$	0.90	$	0.90	$	0.90	$	0.90
*2011:*
Volume (MMBtu)		1,500,000		—		—		—		1,500,000
Price per MMBtu ^(e)	$	0.90		—		—		—	$	0.90


(a)		The index prices for the oil price swaps and collars are based on the NYMEX-West Texas Intermediate monthly average futures price.

(b)		The index price for the natural gas price swap is based on the Inside FERC-El Paso Permian Basin first-of-the-month spot price.

(c)		The index price for the natural gas price swap is based on the NYMEX-Henry Hub last trading day futures price.

(d)		The index price for the natural gas price collar is based on the NYMEX-Henry Hub last trading day futures price.

(e)		The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery point.

(f)		Prices represent weighted average prices.

Interest rate derivative contracts at March 31, 2009. The Company has an interest rate swap which fixes the LIBOR interest rate on the Company’s bank debt at 1.90 percent for three years beginning in May of 2009 on $300 million of the Company’s bank debt. For this portion of the Company’s bank debt, the all-in interest rate will be calculated by adding the fixed rate of 1.90 percent to a margin that ranges from 2.00 percent to 3.00 percent depending on the amount of bank debt outstanding.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

The Company’s reported oil and natural gas revenue and average oil and natural gas prices includes the effects of oil quality and Btu content, gathering and transportation costs, natural gas processing and shrinkage, and the net effect of the commodity hedges that qualified for cash flow hedge accounting. The following table summarizes the gains and losses reported in earnings related to the commodity and interest rate derivative instruments and the net change in accumulated other comprehensive income (“AOCI”):


	Three Months Ended March 31,
(in thousands)	2009			2008

*Decrease in oil and natural gas revenue from derivative activity:*

Cash payments on cash flow hedges in oil sales	$	—		$	(7,206	)
Cash receipts from cash flow hedges in natural gas sales		—			1
Dedesignated cash flow hedges reclassified from AOCI in natural gas sales		—			(296	)

Total decrease in oil and natural gas revenue from derivative activity	$	—		$	(7,501	)


*Loss on derivatives not designated as hedges:*

Mark-to-market loss:
Commodity derivatives	$	(39,743	)	$	(13,191	)
Interest rate derivatives		(2,427	)		—
Cash (payments) receipts on derivatives not designated as hedges:
Commodity derivatives		37,124			(3,987	)
Interest rate derivatives		—			—

Total loss on derivatives not designated as hedges	$	(5,046	)	$	(17,178	)


*Gain from ineffective portion of cash flow hedges*	$	—		$	564


*Accumulated other comprehensive income (loss):*

Cash flow hedges:
Mark-to-market loss of cash flow hedges	$	—		$	(6,606	)
Reclassification adjustment of losses to earnings		—			7,205
Net AOCI upon dedesignation at June 30, 2007		—			—

Net change, before income taxes		—			599
Income tax effect		—			(233	)

Net change, net of income taxes	$	—		$	366


Dedesignated cash flow hedges:
Net AOCI upon dedesignation at June 30, 2007	$	—		$	—
Reclassification adjustment of losses to earnings		—			296
Income tax effect		—			(116	)

Net change, net of income taxes	$	—		$	180

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

Note J. Debt

The Company’s debt consisted of the following:


	March 31,		December 31,
(in thousands)	2009		2008

Credit facility	$	670,750	$	630,000
Less: current portion		—		—

Total long-term debt	$	670,750	$	630,000

Credit facility. The Company’s credit facility, as amended, is subject to scheduled semiannual redeterminations, and has a maturity date of July 31, 2013 (the “Credit Facility”). At March 31, 2009, the Company had letters of credit outstanding under the Credit Facility of approximately $275,000 and its availability to borrow additional funds was $289.0 million. In April 2009, the lenders reaffirmed the Company’s $960 million borrowing base under the Credit Facility until the next scheduled borrowing base redetermination in October 2009. Between scheduled borrowing base redeterminations, the Company and, if requested by 66 2/3 percent of the lenders, the lenders, may each request one special redetermination.

Advances on the Credit Facility bear interest, at the Company’s option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.25 percent at March 31, 2009) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At March 31, 2009, the interest rates of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging from 125 to 275 basis points and zero to 125 basis points, respectively, per annum depending on the debt balance outstanding. At March 31, 2009, the Company pays commitment fees on the unused portion of the available borrowing base ranging from 25 to 50 basis points per annum.

As part of the Company’s April 2009 borrowing base review, the Company agreed to modify the pricing grid on the Credit Facility, effective in April 2009. The interest rates of Eurodollar rate advances and JPM Prime Rate advances will have interest rate margins ranging from 200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per annum depending on the debt balance outstanding. The Company will pay commitment fees on the unused portion of the available borrowing base of 50 basis points per annum.

The Credit Facility also includes a same-day advance facility under which the Company may borrow funds on a daily basis from the administrative agent. Same day advances cannot exceed $25 million and the maturity dates cannot exceed fourteen days. The interest rate on this facility is the JPM Prime Rate plus the applicable interest margin.

The Company’s obligations under the Credit Facility are secured by a first lien on substantially all of the Company’s oil and natural gas properties. In addition, all of the Company’s subsidiaries are guarantors and all general partner, limited partner and membership interests in the Company’s subsidiaries owned by the Company have been pledged to secure borrowings under the Credit Facility. The credit agreement contains various restrictive covenants and compliance requirements which include (a) maintenance of certain financial ratios including (i) maintenance of a quarterly ratio of total debt to consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other noncash income and expenses to be no greater than 4.0 to 1.0, and (ii) maintenance of a ratio of current assets to current liabilities, excluding noncash assets and liabilities related to financial derivatives and asset retirement obligations and including the unfunded amounts under the Credit Facility, to be no less than 1.0 to 1.0; (b) limits on the incurrence of additional indebtedness and certain types of liens; (c) restrictions as to mergers and sales or transfer of assets; and (d) a restriction on the payment of cash dividends. At March 31, 2009, the Company was in compliance with its debt covenants.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

Principal maturities of debt. Principal maturities of debt outstanding at March 31, 2009 are as follows:


(in thousands)

Remaining 2009	$	—
2010		—
2011		—
2012		—
2013		670,750

Total	$	670,750

Interest expense. The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
(in thousands)	2009			2008

Cash payments for interest	$	3,472		$	6,776
Amortization of original issue discount		—			25
Amortization of deferred loan origination costs		856			312
Write-off of deferred loan origination costs and original issue discount		—			—
Net changes in accruals		57			(1,023	)

Interest costs incurred		4,385			6,090
Less: capitalized interest		(15	)		(475	)

Total interest expense	$	4,370		$	5,615

Note K. Commitments and contingencies

Severance agreements. The Company has entered into severance and change of control agreements with all of its officers. The current annual salaries for the Company’s officers covered under such agreements total approximately $2.4 million.

Indemnifications. The Company has agreed to indemnify its directors and officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity.

Legal actions. The Company is a party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company will continue to evaluate litigation involving the Company on a quarter-by-quarter basis and will establish and adjust any reserves as appropriate to reflect its assessment of the then current status of the matters.

Acquisition commitments. In connection with the acquisition of the Henry Entities, the Company agreed to pay certain employees of the Henry Entities bonuses of approximately $11.0 million in the aggregate at each of the first and second anniversaries of the closing of the acquisition of the Henry Entities, respectively. Except as described below, these employees must remain employed with the Company to receive the bonus. A former Henry Entities employee who is otherwise entitled to a full bonus will receive the full bonus (i) if the Company terminates the employee without cause, (ii) upon the death or disability of such employee or (iii) upon a change in control of the Company. If such employee resigns or is terminated for cause, the employee will not receive the bonus and the Company will be required to

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

reimburse the sellers in the acquisition of the Henry Entities 65 percent of the bonus amount not paid to the employee. The Company will reflect the bonus amounts to be paid to these employees as a period cost, which will be included in the Company’s results of operations over the period earned. Amounts that ultimately are determined to be paid to the sellers will be treated as a “contingent purchase price” and reflected as an adjustment to the purchase price. During the three months ended March 31, 2009, the Company recognized $2.6 million of this obligation in its results of operations.

Daywork commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future, including agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which well capital is incurred or rig services are provided. The following table summarizes the Company’s future drilling commitments at March 31, 2009:


	Payments Due By Period
			Less than		1 - 3		3 - 5		More than
(in thousands)	Total		1 year		years		years		5 years

Daywork drilling contracts	$	1,482	$	1,482	$	—	$	—	$	—
Daywork drilling contracts with related parties ^(a)		6,100		6,100		—		—		—
Daywork drilling contracts assumed in the Henry Properties acquisition ^(b)		2,179		1,817		362		—		—

Total contractual drilling commitments	$	9,761	$	9,399	$	362	$	—	$	—


^(a)		Consists of daywork drilling contracts with Silver Oak Drilling, LLC, an affiliate of Chase Oil Corporation.

^(b)		A major oil and gas company which owns an interest in the wells being drilled and the Company are parties to these contracts. Only the Company’s 25% share of the contract obligation has been reflected above.

Operating leases. The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases for the three months ended March 31, 2009 and 2008 were approximately $671,000 and $164,000, respectively. Future minimum lease commitments under non-cancellable operating leases at March 31, 2009 are as follows:


(in thousands)

Remaining 2009	$	975
2010		978
2011		994
2012		981
2013		572

Total	$	4,500

Note L. Income taxes

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109, Accounting for Income Taxes. The Company and its subsidiaries file federal corporate income tax returns on a consolidated basis. The tax returns and the amount of taxable income or loss are subject to examination by United States federal and state taxing authorities. In determining the interim period income tax provision, the Company utilizes an estimated annual effective tax rate.

The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, (“FIN No. 48”) an interpretation of FASB Statement No. 109, Accounting for Income Taxes, on January 1, 2007. At the time of adoption and at

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

March 31, 2009, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2004 through 2008 remain subject to examination by major tax jurisdictions.

The FASB issued FIN No. 48-1, Definition of Settlement in FASB Interpretation No. 48, (“FIN No. 48-1”) to clarify when a tax position is effectively settled. FIN No. 48-1 provides guidance in determining the proper timing for recognizing tax benefits and applying the new information relevant to the technical merits of a tax position obtained during a tax authority examination. FIN No. 48-1 provides criteria to determine whether a tax position is effectively settled after completion of a tax authority examination, even if the potential legal obligation remains under the statute of limitations. The Company’s adoption of this pronouncement did not have a significant effect on its consolidated financial statements.

Income tax provision. The Company’s income tax provision and amounts separately allocated were attributable to the following items for the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
(in thousands)	2009			2008

Income (loss) from operations	$	(8,106	)	$	14,368

Changes in stockholders’ equity:
Net deferred hedge losses		—			(2,582	)
Net settlement losses included in earnings		—			2,932
Tax benefits related to stock-based compensation		(804	)		(593	)

	$	(8,910	)	$	14,125

The Company’s income tax provision (benefit) attributable to income (loss) from operations consisted of the following for the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
(in thousands)	2009			2008

*Current:*
U.S. federal	$	2,438		$	—
U.S. state and local		327			—

		2,765			—


*Deferred:*
U.S. federal		(9,585	)		12,054
U.S. state and local		(1,286	)		2,314

		(10,871	)		14,368

	$	(8,106	)	$	14,368

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

The reconciliation between the tax expense computed by multiplying pretax income by the U.S. federal statutory rate and the reported amounts of income tax expense is as follows:


	Three Months Ended March 31,
(in thousands)	2009			2008

Income (loss) at U.S. federal statutory rate	$	(7,466	)	$	12,857
State income taxes (net of federal tax effect)		(623	)		1,504
Nondeductible expense & other		(17	)		7

Expense (benefit) for income taxes	$	(8,106	)	$	14,368

Note M. Related parties

Chase Group transactions. The Company incurred charges from Mack Energy Corporation (“MEC”), an affiliate of Chase Oil Corporation (“Chase Oil”) of approximately $0.3 million and $1.5 million for the three months ended March 31, 2009 and 2008, respectively, for services rendered in the ordinary course of business.

The Company had $139,000 in outstanding receivables due from MEC at March 31, 2009 and no outstanding receivables due from MEC at December 31, 2008. The Company had $5,000 in outstanding invoices payable to MEC at March 31, 2009 and no outstanding invoices payable to MEC at December 31, 2008.

Saltwater disposal services agreement. Among the assets the Company acquired from Chase Oil is an undivided interest in a saltwater gathering and disposal system, which is owned and maintained under a written agreement among the Company and Chase Oil and certain of its affiliates, and under which the Company as operator gathers and disposes of produced water. The system is owned jointly by the Company and Chase Oil and its affiliates in undivided ownership percentages, which are annually redetermined as of January 1 on the basis of each party’s percentage contribution of the total volume of produced water disposed of through the system during the prior calendar year. As of January 1, 2009, the Company owned 95.4% of the system and Chase Oil and its affiliates owned 4.6%.

Other related party transactions. The Company also has engaged in transactions with certain other affiliates of Chase Oil, Caza Energy LLC (“Caza”) and certain other parties thereto (collectively the “Chase Group”), including a drilling contractor, an oilfield services company, a supply company, a drilling fluids supply company, a pipe and tubing supplier, a fixed base operator of aircraft services and a software company.

The Company incurred charges from these related party vendors of approximately $6.4 million and $15.1 million for the three months ended March 31, 2009 and 2008, respectively.

The Company had outstanding amounts payable to the other related party vendors identified above of approximately $781,000 and $21,000 at March 31, 2009 and December 31, 2008, respectively, which are reflected in accounts payable—related parties in the accompanying consolidated balance sheets.

Overriding royalty and royalty interests. Certain members of the Chase Group own overriding royalty interests in certain of the Chase Group properties. The amount paid attributable to such interests was approximately $241,000 and $784,000 for the three months ended March 31, 2009 and 2008, respectively. The Company owed these owners royalty payments of approximately $80,000 and $146,000 at March 31, 2009 and December 31, 2008, respectively.

Royalties are paid on certain properties located in Andrews County, Texas to a partnership of which one of the Company’s directors is the general partner, and who also owns a 3.5% partnership interest. The Company paid this partnership approximately $26,000 and $83,000 for the three months ended March 31, 2009 and 2008, respectively. The Company owed this partnership royalty payments of approximately $7,000 and $13,000 at March 31, 2009 and December 31, 2008.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

In April 2005, the Company acquired certain working interests in 46,861 gross (26,908 net) acres located in Culberson County, Texas from an entity partially owned by a person who became an executive officer of the Company immediately following such acquisition. In connection with this acquisition, such entity retained a 2% overriding royalty interest in the acquired properties, which overriding royalty interest later became owned equally by such officer and a non-officer employee of the Company. During the three months ended March 31, 2009 and 2008, no payments were made related to this overriding royalty interest. Effective March 31, 2008, the executive officer involved in this matter resigned from the Company.

Working interests owned by employees. As part of the Henry Properties acquisition, the Company purchased oil and natural gas properties in which employees owned a working interest. The Company distributed revenues to these employees totaling approximately $30,000 and received joint interest payments from these employees of approximately $639,000 for the three months ended March 31, 2009. At March 31, 2009 and December 31, 2008, the Company was owed by these employees approximately $121,000 and $300,000, respectively, which is reflected in accounts receivable — related parties.

Note N. Net income (loss) per share

Basic net income (loss) per share is computed by dividing net income (loss) applicable to common shareholders by the weighted average number of common shares treated as outstanding for the period. All capital options were exercised prior to March 31, 2008.

The computation of diluted income (loss) per share reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to income (loss) were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. These amounts include unexercised stock options and restricted stock (as issued under the Plan and described in Note G). Potentially dilutive effects are calculated using the treasury stock method.

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding:


	Three Months Ended March 31,
(in thousands)	2009		2008

*Weighted average common shares outstanding:*

Basic		84,529		75,473
Dilutive capital options		—		23
Dilutive common stock options		—		1,156
Dilutive restricted stock		—		234

Diluted		84,529		76,886

For the three months ended March 31, 2009, the computation of diluted net loss per share was antidilutive; therefore, the amounts reported for basic and diluted net loss per share were the same. For the three months ended March 31, 2009, 484,376 shares of restricted stock and 2,600,769 stock options were not included in the computation of diluted loss per share, as inclusion of these items would be antidilutive.

For the three months ended March 31, 2008, the effects of all potentially dilutive securities, including capital options, stock options and restricted stock were included in the computation of diluted earnings per share because there were no antidilutive effects.

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

Note O. Other current liabilities

The following table provides the components of the Company’s other current liabilities at March 31, 2009 and December 31, 2008:


	March 31,		December 31,
(in thousands)	2009		2008

*Other current liabilities:*
Accrued production costs	$	20,455	$	15,489
Payroll related matters		12,625		11,290
Accrued interest		410		353
Asset retirement obligations		2,853		2,611
Other		—		8,314

Other current liabilities	$	36,343	$	38,057

Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
March 31, 2009
Unaudited

Note P. Supplementary information

Capitalized costs


	March 31,			December 31,
(in thousands)	2009			2008

*Oil and natural gas properties:*
Proved	$	2,453,517		$	2,316,330
Unproved		337,518			377,244
Less: accumulated depletion		(357,585	)		(306,990	)

Net capitalized costs for oil and natural gas properties	$	2,433,450		$	2,386,584


*Costs incurred for oil and natural gas producing activities* (a)

	Three Months Ended March 31,
(in thousands)	2009			2008

Property acquisition costs:^(b)
Proved	$	(940	)	$	105
Unproved		1,221			762
Exploration		23,809			29,565
Development		83,779			24,877

Total costs incurred for oil and natural gas properties	$	107,869		$	55,309



(a) The costs incurred for oil and natural gas producing activities includes the following amounts of asset retirement obligations:

	Three Months Ended March 31,
(in thousands)	2009			2008

Proved property acquisition costs	$	—		$	—
Exploration costs		168			26
Development costs		999			(802	)

Total	$	1,167		$	(776	)


(b)		During the three months ended March 31, 2009, the Company adjusted the purchase price allocation related to the acquisition of the Henry Properties. This adjustment reduced the proved acquisition costs by $940,000 and increased the unproved acquisition costs by $591,000.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data included in our Annual Report on Form 10-K for the year ended December 31, 2008.

During the third quarter of 2008, the Company closed a significant acquisition as discussed below. As a result of the acquisition many comparisons between periods will be difficult or impossible.

Statements in this discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenue and expenses to differ materially from our expectations. See “Cautionary statement regarding forward-looking statements.”

Overview

We are an independent oil and natural gas company engaged in the acquisition, development, exploitation and exploration of producing oil and natural gas properties. Our operations are primarily focused in the Permian Basin of Southeastern New Mexico and West Texas. We have also acquired significant acreage positions in and are actively involved in drilling or participating in drilling in emerging plays located in the Permian Basin of Southeastern New Mexico and the Williston Basin in North Dakota, where we are applying horizontal drilling and advanced fracture stimulation. Oil comprised 62.9 percent of our 137.3 MMBoe of estimated net proved reserves at December 31, 2008, and 64.8 percent of our 7.1 MMBoe of production in 2008. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 93.1 percent of our proved developed producing PV-10 and 64.7 percent of our 3,553 gross wells at December 31, 2008. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and stimulation methods used.

Commodity prices

Factors that may impact future commodity prices, including the price of oil and natural gas, include:

	•		developments generally impacting the Middle East, specifically Iraq and Iran;

	•		the extent to which members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations are able to continue to manage oil supply through export quotas;

	•		the overall global demand for oil; and

	•		overall North American natural gas supply and demand fundamentals, including:

	§		the impact of the decline of the United States economy,

	§		weather conditions and

	§		liquefied natural gas deliveries to the United States.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity hedge positions at March 31, 2009.

Oil prices in 2008 were high and particularly volatile compared to historical prices. The NYMEX oil price per Bbl averaged $43.30 and $97.74 for the three months ended March 31, 2009 and 2008, respectively. In addition, natural gas prices have been subject to significant fluctuations during the past several years. The NYMEX natural gas price per MMBtu averaged $4.49 and $8.73 for the three months ended March 31, 2009 and 2008, respectively. Further demonstrating the continuing volatility, the NYMEX oil price and NYMEX natural gas price reached lows of $45.88 per Bbl and $3.25 per MMBtu, respectively, during the period from April 1, 2009 to May 4, 2009. At May 4, 2009, the NYMEX oil price and NYMEX natural gas price were $54.47 per Bbl and $3.73 per MMBtu, respectively.

Henry Entities acquisition

On July 31, 2008, we closed the acquisition of Henry Petroleum LP and certain entities affiliated with Henry Petroleum LP (referred to as “Henry” or the “Henry Entities”) and additional non-operated interests in oil and natural gas properties from persons affiliated with the Henry Entities. In August 2008 and September 2008, we acquired additional non-operated interests in oil and natural gas properties from persons affiliated with the Henry Entities. The assets acquired in the Henry Entities acquisition, including the additional non-operated interests, are referred to as the “Henry Properties.” We paid $584.1 million in cash for the Henry Properties acquisition, which was funded with borrowings under our credit facility which was amended and restated on July 31, 2008, and net proceeds of approximately $242.4 million from our private placement of 8,302,894 shares of our common stock.

2009 capital budget

On November 6, 2008, our board of directors approved a capital budget for 2009 of up to approximately $500 million, predicated on funding it substantially within our cash flow. The following is a summary of our 2009 capital budget:


	2009
(in millions)	Budget

Drilling and recompletion opportunities in our core operating area	$	398
Projects operated by third parties		8
Emerging plays, acquisition of leasehold acreage and other property interests, and geological and geophysical		72
Maintenance capital in our core operating areas		22

Total 2009 capital budget	$	500

In light of a drop in commodity prices, we took the following actions in January 2009:

	•		reduced our operated drilling rig count in the Wolfberry play from eight to five;

	•		deferred our deepening program on our Southeastern New Mexico shelf properties; and

	•		deferred certain drilling activity in the Lower Abo horizontal play.

The annualized effect of these changes in operating activity would reduce our 2009 capital spending to approximately $300 million, assuming our current estimate of 2009 capital costs. We will continue to monitor our capital expenditures in relation to our cash flow and expect to adjust our activity and capital spending level based on changes in commodity prices and the cost of goods and services and other considerations.

During the first quarter of 2009, we incurred approximately $107.1 million of capital expenditures (excluding the effects of asset retirement obligations and adjustment to the acquisition of the Henry Properties). These costs were in excess of our cash flows (including effects of derivative cash receipts) during the first quarter of 2009. We expected to outspend our cash flow in the first quarter of 2009, but we expect that our capital spending for 2009 will be substantially within our cash flow. Currently, we believe that our 2009 capital spending will be approximately $300 million based on current capital costs and estimated cash flows.

Recent events

Reaffirmed borrowing base. We amended our credit agreement on April 7, 2009, to (i) reaffirm our borrowing base of $960 million, (ii) add certain provisions relating to defaulting lenders which, among other things, require, at the request of the administrative agent, us to cash collateralize or prepay a defaulting lender’s pro rata share of letter of credit and swingline loan exposure, (iii) amend the calculation of alternate base rate interest, which is used in connection with non-Eurodollar rate loans from the greater of (a) the JPMorgan Chase Bank prime rate or (b) the federal funds rate plus 0.50% to the greatest of the (x) JPMorgan Chase Bank prime rate, (y) the federal funds rate plus 0.50% and (z) the rate for one-month U.S. dollar deposits in the London interbank market plus 1.00% and (iv) revise the pricing schedule to (a) increase the Eurodollar rate margin from a range of 1.25% to 2.75% to a range of 2.00% to 3.00% (depending on the then-current borrowing base usage), (b) increase the alternate base rate margin from a range of 0.00% to 1.25% to a range of 1.125% to 2.125% (depending on the then-current borrowing base usage), and (c) increase the unused commitment fee rate from a range of 0.25% to 0.50% to a flat rate of 0.50%.

Short-term interruptions in production. During the first quarter of 2008, we experienced short-term interruptions in our production on the New Mexico shelf properties due to operational problems with a natural gas processing plant. There were a total of ten days of curtailment during the first quarter, and approximately 17 MBoe of our production was curtailed during this period.

Derivative financial instrument exposure. At March 31, 2009, the fair value of our financial derivatives was a net asset of $130.3 million. All of our counterparties to these financial derivatives are party to our credit facility and have their outstanding debt commitments and derivative exposures collateralized pursuant to our credit facility. Pursuant to the terms of our financial derivative instruments and their collateralization under our credit facility, we do not have exposure to potential “margin calls” on our financial derivative instruments.

Most of our commodity derivative instruments are currently in a net asset position to us. We currently have no reason to believe that our counterparties to these commodity derivative contracts are not financially viable. Our credit facility does not allow us to offset amounts we may owe a lender under our credit facility against amounts we may be owed related to our financial instruments with such party.

New commodity derivative contracts. During the three months ended March 31, 2009, we entered into additional commodity derivative contracts to economically hedge a portion of our estimated future production. The following table summarizes information about these additional commodity derivative contracts:

Aggregate

Daily

Index

Contract

Volume

Price

Period

Oil (volumes in Bbls):

Price swap

540,000

2,935

$51.62 ^(a)

7/1/09 - 12/31/09

Price swap

1,608,000

4,405

$55.83 ^(a)

1/1/10 - 12/31/10

Price collar

600,000

6,522

$45.00 - $49.00^{(a) (e)}

3/1/09 - 5/31/09

Natural gas (volumes in MMBtus):

Price swap

3,000,000

16,393

$4.31 ^(b)

4/1/09 - 9/30/09

Price collar

9,000,000

16,453

$5.42 - $6.12^{(c) (e)}

10/1/09 - 3/31/11

Basis swap

7,500,000

16,484

$0.90 ^(d)

1/1/10 - 3/31/11


(a)		The index prices for the oil price swaps and collars are based on the NYMEX-West Texas Intermediate monthly average futures price.

(b)		The index price for the natural gas price swap is based on the NYMEX-Henry Hub last trading day futures price.

(c)		The index price for the natural gas price collar is based on the NYMEX-Henry Hub last trading day futures price.

(d)		The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery point.

(e)		Prices represent weighted average prices.

Results of Operations

The following table presents selected operating information for the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
	2009		2008

Net production volumes:
Oil (MBbl)		1,687		887
Natural gas (MMcf)		4,955		3,105
Total (MBoe)		2,513		1,405

Average daily production volumes:
Oil (Bbl)		18,744		9,747
Natural gas (Mcf)		55,056		34,121
Total (Boe)		27,922		15,440

Average prices:
Oil, without hedges (Bbl)	$	38.51	$	93.60
Oil, with hedges (Bbl)	$	38.51	$	85.48
Natural gas, without hedges (Mcf)	$	4.24	$	10.04
Natural gas, with hedges (Mcf)	$	4.24	$	9.95
Total, without hedges (Boe)	$	34.22	$	81.29
Total, with hedges (Boe)	$	34.22	$	75.95

Three months ended March 31, 2009, compared to three months ended March 31, 2008

Oil and natural gas revenues. Revenue from oil and natural gas operations was $86.0 million for the three months ended March 31, 2009, a decrease of $20.7 million (19 percent) from $106.7 million for the three months ended March 31, 2008. This decrease was primarily due to substantial decreases in realized oil and natural gas prices, offset by increased production (i) as a result of the acquisition of the Henry Entities on July 31, 2008 and (ii) due to successful drilling efforts during 2008 and 2009. Specifically the:


	•		average realized oil price (after giving effect to hedging activities) was $38.51 per Bbl during the three months ended March 31, 2009, a decrease of 55 percent from $85.48 per Bbl during the three months ended March 31, 2008;

	•		total oil production was 1,687 MBbl for the three months ended March 31, 2009, an increase of 800 MBbl (90 percent) from 887 MBbl for the three months ended March 31, 2008;

	•		average realized natural gas price (after giving effect to hedging activities) was $4.24 per Mcf during the three months ended March 31, 2009, a decrease of 57 percent from $9.95 per Mcf during the three months ended March 31, 2008;

	•		total natural gas production was 4,955 MMcf for the three months ended March 31, 2009, an increase of 1,850 MMcf (60 percent) from 3,105 MMcf for the three months ended March 31, 2008;

	•		average realized barrel of oil equivalent price (after giving effect to hedging activities) was $34.22 per Boe during the three months ended March 31, 2009, a decrease of 55 percent from $75.95 per Boe during the three months ended March 31, 2008; and

	•		total production was 2,513 MBoe for the three months ended March 31, 2009, an increase of 1,108 MBoe (79 percent) from 1,405 MBoe for the three months ended March 31, 2008.

See discussion in “—Recent events” about our 2008 production interruptions.

Hedging activities. The oil and natural gas prices that we report are based on the market price received for the commodities adjusted to give effect to the results of our cash flow hedging activities. We utilize commodity derivative instruments in order to (i) reduce the effect of the volatility of price changes on the commodities we produce and sell, (ii) support our capital budget and expenditure plans and (iii) support the economics associated with acquisitions.

Currently, we do not designate our derivative instruments to qualify for hedge accounting. Accordingly, we reflect the changes in the fair value of our derivative instruments in the statements of operations as (gain) loss on derivatives not designated as hedges. All of our remaining hedges that historically qualified or were dedesignated from hedge accounting were settled in 2008.

The following is a summary of the effects of commodity hedges that qualify for hedge accounting treatment for the three months ended March 31, 2008:


	Oil Hedges			Natural Gas Hedges
	Three Months Ended			Three Months Ended
	March 31, 2008			March 31, 2008

Hedging revenue increase (decrease) (in thousands)	$	(7,206	)	$	(296	)
Hedged volumes (Bbls and MMBtus, respectively)		236,600			1,228,500
Hedged revenue increase (decrease) per hedged volume	$	(30.46	)	$	(0.24	)

Production expenses. The following tables provide the components of our total oil and natural gas production costs for the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
	2009				2008
			Per					Per
(in thousands, except per unit amounts)	Amount		Boe			Amount		Boe

Lease operating expenses	$	16,568	$	6.59		$	6,942	$	4.94
Taxes:
Ad valorem		1,502		0.60			488		0.35
Production		6,275		2.50			9,078		6.46
Workover costs		421		0.17			387		0.28

Total oil and gas production expenses	$	24,766	$	9.86		$	16,895	$	12.03

Among the cost components of production expenses, in general, we have control over lease operating expenses and workover costs on properties we operate, but production and ad valorem taxes are directly related to commodity price changes.

Lease operating expenses were $16.6 million ($6.59 per Boe) for the three months ended March 31, 2009, an increase of $9.7 million (141 percent) from $6.9 million ($4.94 per Boe) for the three months ended March 31, 2008. The increase in lease operating expenses is due to (i) the wells acquired in the Henry Properties acquisition, which increased the absolute and per unit amount because those wells have a higher per unit cost as compared to our historical per unit cost, (ii) our wells successfully drilled and completed in 2008 and 2009 and (iii) general inflation of field service and supply costs associated with rising commodity prices.

Ad valorem taxes have increased primarily as a result of the Henry Properties acquisition, which were highly concentrated in Texas, a state which has a higher ad valorem rate than New Mexico, where substantially all of our properties prior to the acquisition were located.

Production taxes per unit of production were $2.50 per Boe during the three months ended March 31, 2009, a decrease of 61 percent from $6.46 per Boe during the three months ended March 31, 2008. The decrease is directly related to the decrease in commodity prices offset by the increase in oil and natural gas revenues related to increased volumes. Over the same period our Boe prices (before the effects of hedging) decreased 58 percent.

Workover expenses were approximately $0.4 million for the three months ended March 31, 2009 and 2008. The 2009 and 2008 amounts related primarily to workovers in Andrews County, Texas.

Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
(in thousands)	2009		2008

Geological and geophysical	$	677	$	1,893
Exploratory dry holes		1,421		18
Leasehold abandonments and other		3,897		830

Total exploration and abandonments	$	5,995	$	2,741

Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, during the three months ended March 31, 2009 was $0.7 million, a decrease of $1.2 million from $1.9 million for the three months ended March 31, 2008. This decrease is primarily attributable to a comprehensive seismic survey on our New Mexico shelf properties which was initiated in December 2007 and completed in 2008.

During the three months ended March 31, 2009, we wrote-off an unsuccessful exploratory well in our Arkansas emerging play.

For the three months ended March 31, 2009, we recorded approximately $3.9 million of leasehold abandonments, which relates primarily to the write-off of one prospect in New Mexico and two prospects in Texas. For the three months ended March 31, 2008, we recorded $0.8 million of leasehold abandonments, which were primarily related to prospects in Chaves and Eddy Counties, New Mexico and Andrews County, Texas.

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
	2009				2008
			Per				Per
(in thousands, except per unit amounts)	Amount		Boe		Amount		Boe

Depletion of proved oil and natural gas properties	$	49,777	$	19.81		$20,926	$	14.89
Depreciation of other property and equipment		578		0.23		358		0.25
Amortization of intangible asset — operating rights		393		0.16		—		—

Total depletion, depreciation and amortization	$	50,748	$	20.20		$21,284	$	15.14


Crude oil price used to estimate proved oil reserves at period end	$	44.63			$	98.00
Natural gas price used to estimate proved gas reserves at period end	$	3.63			$	9.37

Depletion of proved oil and natural gas properties was $49.8 million ($19.81 per Boe) for the three months ended March 31, 2009, an increase of $28.9 million from $20.9 million ($14.89 per Boe) for the three months ended March 31, 2008. The increase in depletion expense was primarily due to (i) the Henry Properties acquisition for which the depletion rate was higher than that of our historical assets, (ii) capitalized costs associated with new wells that were successfully drilled and completed in 2008 and 2009 and (iii) the decrease in the oil and natural gas prices between the years utilized to determine proved reserves.

The amortization of the intangible asset is a result of the value assigned to the operating rights that we acquired in the Henry Properties acquisition. The intangible asset is currently being amortized over an estimated life of approximately 25 years.

Impairment of long-lived assets. We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. As a result of this review of the recoverability of the carrying value of our assets during the three months ended March 31, 2009, we recognized a non-cash charge against earnings of $4.1 million, which was primarily attributable to leases in Eddy Counties, New Mexico. For the three months ended March 31, 2008, we recognized a non-cash charge against earnings of $0.02 million, which was primarily attributable to a lease located in Kent County, Texas.

General and administrative expenses. The following table provides components of our general and administrative expenses for the three months ended March 31, 2009 and 2008:


	Three Months Ended March 31,
	2009						2008
				Per						Per
(in thousands, except per unit amounts)	Amount			Boe			Amount			Boe

General and administrative expenses — recurring	$	9,914		$	3.95		$	6,620		$	4.71
Non-recurring bonus paid to former Henry Entities’ employees		2,561			1.02			—			—
Non-cash stock-based compensation — stock options		1,028			0.41			905			0.64
Non-cash stock-based compensation — restricted stock		897			0.36			394			0.28
Less: Third-party operating fee reimbursements		(2,654	)		(1.06	)		(239	)		(0.16	)

Total general and administrative expenses	$	11,746		$	4.68		$	7,680		$	5.47

General and administrative expenses were $11.7 million ($4.68 per Boe) for the three months ended March 31, 2009, an increase of $4.0 million (52 percent) from $7.7 million ($5.47 per Boe) for the three months ended March 31, 2008. The increase in general and administrative expenses during the three months ended March 31, 2009 over 2008 was primarily due to (i) the non-recurring bonus paid to Henry Entities’ employees, (ii) an increase in non-cash stock-based compensation for both stock options and restricted stock awards and (iii) an increase in the number of employees and related personnel expenses, partially offset by an increase in third-party operating fee reimbursements.

In connection with the Henry Entities acquisition, we agreed to pay certain of the Henry Entities’ former employees a predetermined bonus amount, in addition to the compensation we pay these employees, over the next two years. Since these employees will earn this bonus over the next two years, we are reflecting the cost in our general and administrative costs as non-recurring, as it is not controlled by us. See Note K of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited) “ for additional information related to this bonus.

We earn reimbursements as operator of certain oil and natural gas properties in which we own interests. As such, we earned reimbursements of $2.7 million and $0.2 million during the three months ended March 31, 2009 and 2008, respectively. This reimbursement is reflected as a reduction of general and administrative expenses in the consolidated statements of operations. The increase in this reimbursement is directly related to the Henry Properties acquisition, as we own a lower working interest in these operated properties compared to our historical property base, so we receive a larger third-party reimbursement as compared to our historical property base.

Loss on derivatives not designated as hedges. During the three months ended June 30, 2007, we determined that all of our natural gas commodity derivative contracts no longer qualified as hedges. Because we no longer considered these hedges to be highly effective, we discontinued hedge accounting for those existing hedges, prospectively, and during the period the hedges became ineffective. In addition, for our new commodity and interest rate derivative contracts entered into after August 2007, we chose not to designate any of these contracts as hedges. As a result, any changes in fair value and any cash settlements related to these contracts are recorded in earnings during the related period. All amounts previously recorded in accumulated other comprehensive income were reclassified to earnings prior to 2009.

For the three months ended March 31, 2009, the related cash receipts for settlements for derivative contracts not designated as hedges was approximately $37.1 million. The non-cash mark-to-market adjustment for the derivative contracts not designated as hedges was a loss of $42.2 million. This is compared to cash payments for settlements of $4.0 million and non-cash mark-to-market losses of $13.2 million for the three months ended March 31, 2008.

Interest expense. Interest expense was $4.4 million for the three months ended March 31, 2009, a decrease of $1.2 million from $5.6 million for the three months ended March 31, 2008. The weighted average interest rate for the three months ended March 31, 2009 and 2008 was 2.0% and 6.7%, respectively. The weighted average debt balance during the three months ended March 31, 2009 and 2008 was approximately $655.9 million and $324.5 million, respectively.

The increase in weighted average debt balance during the three months ended March 31, 2009 was due primarily to borrowings in July 2008 for the acquisition of the Henry Properties. The increase in interest expense is due to an increase in the weighted average

debt balance offset by a decrease in the weighted average interest rate. The decrease in the weighted average interest rate is primarily due to an improvement in market interest rates.

Income tax provisions. We recorded an income tax benefit of $8.1 million and income tax expense of $14.4 million for the three months ended March 31, 2009 and 2008, respectively. The effective income tax rate for the three months ended March 31, 2009 and 2008 was 38.0 percent and 39.1 percent, respectively. We estimated a higher effective state income rate in 2008 than in 2009, which is primarily due to our estimate of income among the various states in which we own assets.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, proceeds from the disposition of assets or alternative financing sources as discussed in “Capital resources” below.

Oil and natural gas properties. Our capital expenditures on oil and natural gas properties, excluding acquisitions and asset retirement obligations, during the three months ended March 31, 2009 and 2008 totaled $106.4 million and $55.2 million, respectively. These expenditures were primarily funded by cash flow from operations.

On November 6, 2008, our board of directors approved a capital budget for 2009 of up to approximately $500 million. The capital budget is predicated on funding it substantially within cash flow. In light of the recent drop in commodity prices we took the following actions in January 2009:

	•		reduced our operated drilling rig count in the Wolfberry play from eight to five;

	•		deferred our deepening program on our Southeastern New Mexico shelf properties; and

	•		deferred certain drilling activity in the Lower Abo horizontal play.

The annualized effect of these changes in operating activity would reduce the Company’s 2009 capital spending to approximately $300 million, assuming the Company’s current estimate of 2009 capital costs and estimated cashflows. We will monitor our capital expenditures in relation to our cash flow on a quarterly basis and will adjust our activity and capital spending level based on changes in commodity prices and the cost of goods and services.

Other than the purchase of leasehold acreage and other miscellaneous property interests, our 2009 capital budget is exclusive of acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of exploitation, development, high-potential exploration and control of operations and that will allow us to apply our operating expertise.

Although we cannot provide any assurance, we believe that our available cash and our cash flows will be sufficient to fund our 2009 capital expenditures, as adjusted from time to time; however, we could also use our credit facility to fund such expenditures. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. In addition, under certain circumstances we would consider increasing or reallocating our 2009 capital budget.

Acquisitions. Our expenditures for acquisitions of proved and unproved properties during the three months ended March 31, 2009 and 2008 totaled $1.8 million and $0.9 million, respectively. The Henry Properties acquisition in July 2008 was primarily funded by a private placement of our common stock and borrowings under our credit facility.

Contractual obligations. Our contractual obligations include long-term debt, operating lease obligations, drilling commitments (including commitments to pay day rates for drilling rigs), employment agreements, contractual bonus payments, derivative obligations and other liabilities. Since December 31, 2008, the material changes in our contractual obligations included a $40.8 million increase in outstanding long-term borrowings, a $42.2 million decrease in our net commodity derivative obligations, and a $19.0 million decrease in our drilling commitments. See Note K of Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our long-term debt and “Item 3.

Quantitative and Qualitative Disclosures About Market Risk” for information regarding the interest on our long-term debt and information on changes in the fair value of our open derivative obligations during the three months ended March 31, 2009.

Off-balance sheet arrangements. Currently, we do not have any material off-balance sheet arrangements.

Capital resources. Our primary sources of liquidity have been cash flows generated from operating activities and financing provided by our credit facility. We believe that funds from operating cash flows and our credit facility should be sufficient to meet both our short-term working capital requirements and our 2009 capital budget plans.

Cash flow from operating activities. Our net cash provided by operating activities was $40.6 million and $69.8 million for the three months ended March 31, 2009 and 2008, respectively. The decrease in operating cash flows during the three months ended March 31, 2009 over 2008 was principally due to (i) decreases in average realized oil and natural gas prices, (ii) increases in oil and natural gas production costs and general and administrative expenses and (iii) uses of funds associated with working capital.

Cash flow used in investing activities. During the three months ended March 31, 2009 and 2008, we invested $131.6 million and $51.5 million, respectively, for additions to, and acquisitions of, oil and natural gas properties, inclusive of dry hole costs. Cash flows used in investing activities were substantially higher during the three months ended March 31, 2009 over 2008, due to an increase in our exploration and development activities, offset by the receipts / payments associated with derivatives not designated as hedges.

Cash flow from financing activities. Net cash provided by financing activities was $38.6 million and $27.2 million for the three months ended March 31, 2009 and 2008, respectively. During the three months ended March 31, 2009, we had net borrowings of $40.8 million under our credit facility. During the three months ended March 31, 2008, we reduced our outstanding balance by $26.0 million on our credit facilities utilizing cash from operations.

Our credit facility, as amended, is subject to scheduled semiannual redeterminations, and has a maturity date of July 31, 2013 (the “Credit Facility”). At March 31, 2009, we had letters of credit outstanding under the Credit Facility of approximately $275,000 and our availability to borrow additional funds was $289.0 million. In April 2009, the lenders reaffirmed our $960 million borrowing base under the Credit Facility until the next scheduled borrowing base redetermination in October 2009. Between scheduled borrowing base redeterminations, we and, if requested by 66 2/3 percent of the lenders, the lenders, may each request one special redetermination.

Advances on the Credit Facility bear interest, at our option, based on (i) the prime rate of JPMorgan Chase Bank (“JPM Prime Rate”) (3.25 percent at March 31, 2009) or (ii) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). At March 31, 2009, the interest rates of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging from 125 to 275 basis points and zero to 125 basis points, respectively, per annum depending on the debt balance outstanding. At March 31, 2009, we pay commitment fees on the unused portion of the available borrowing base ranging from 25 to 50 basis points per annum.

As part of our April 2009 borrowing base review, we agreed to modify the pricing grid on the Credit Facility, effective in April 2009. The interest rates of Eurodollar rate advances and JPM Prime Rate advances will have interest rate margins ranging from 200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per annum depending on the debt balance outstanding. We will pay commitment fees on the unused portion of the available borrowing base of 50 basis points per annum.

In conducting our business, we may utilize various financing sources, including the issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock (iv) common stock and (v) other securities. We may also sell assets and issue securities in exchange for oil and natural gas assets or interests in oil and natural gas companies. Additional securities may be of a class senior to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined from time to time by our board of directors. Utilization of some of these financing sources may require approval from the lenders under our Credit Facility.

Financial markets. The current state of the financial markets is uncertain. There have been financial institutions that have (i) failed and been forced into government receivership, (ii) declared bankruptcy, (iii) been forced to seek additional capital and liquidity to maintain viability or (iv) merged. The United States and world economy is experiencing volatility which is having an adverse impact on the financial markets.

At March 31, 2009, we had $289.0 million of available borrowing capacity under our credit facility. Even in light of the current volatility in the financial markets, we currently believe that the lenders under our credit facility have the ability to fund additional borrowings we may need for our business.

We currently pay floating rate interest under our credit facility and we are unable to predict, especially in light of the current uncertainty in the financial markets, whether we will incur increased interest costs due to rising interest rates. We have utilized the use of interest rate derivatives to mitigate the cost of rising interest rates, and we may enter into additional interest rate derivatives in the future.

In the current financial markets, we do not believe that we could refinance our credit facility and obtain comparable terms. Since our credit facility matures in July 2013, we have no immediate need to seek refinancing of our credit facility.

To the extent we need additional funds, beyond those available under our credit facility, to operate our business or make acquisitions we would have to pursue other financing sources. These sources could include issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) additional common stock or (v) other securities. We may also sell assets. However, in light of the current financial markets there are no assurances that we could obtain additional funding, or if available, at what cost and terms.

Liquidity. Our principal sources of short-term liquidity are cash on hand and available borrowing capacity under our credit facility. At March 31, 2009, we had $2.4 million of cash on hand.

At March 31, 2009, the borrowing base under our credit facility was $960 million, which provides us with $289.0 million of available borrowing capacity. Our borrowing base is redetermined semi-annually, with the next redetermination occurring in October 2009. In addition to such semi-annual redeterminations, our lenders may request one additional redetermination during any twelve-month period. In general, redeterminations are based upon a number of factors, including commodity prices and reserve levels. Upon a redetermination, our borrowing base could be substantially reduced. In light of the current commodity prices and the state of the financial markets, there is no assurance that our borrowing base will not be reduced.

Book capitalization and current ratio. Our book capitalization at March 31, 2009 was $1,987.4 million, consisting of debt of $670.8 million and stockholders’ equity of $1,316.7 million. Our debt to book capitalization was 34 percent and 32 percent at March 31, 2009 and December 31, 2008, respectively. Our ratio of current assets to current liabilities was 1.01 to 1.00 at March 31, 2009 as compared to 1.03 to 1.00 at December 31, 2008.

Inflation and changes in prices. Our revenues, the value of our assets, our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the three months ended March 31, 2009, we received an average of $38.51 per barrel of oil and $4.24 per Mcf of natural gas before consideration of commodity derivative contracts compared to $93.60 per barrel of oil and $10.05 per Mcf of natural gas in the three months ended March 31, 2008. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and continued through the first six months of 2008, commodity prices for oil and natural gas increased significantly. The higher prices have led to increased activity in the industry and, consequently, rising costs. These cost trends have put pressure not only on our operating costs but also on capital costs. We expect these costs to moderate during 2009 as a result of the recent rapid diminution in prices for oil and natural gas from 2008 peaks.

Critical Accounting Policies, Practices and Estimates

Our historical consolidated financial statements and related notes to consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to us.

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are revenue recognition, the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets and valuation of stock-based compensation. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates, as additional information becomes known.

There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2009. See our disclosure of critical accounting policies in the consolidated financial statements on our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on February 27, 2009.

Recent Accounting Pronouncements and Developments

Recent accounting pronouncements. In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 141(R), Business Combinations (“SFAS No. 141(R)”), which replaces FASB Statement No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. We adopted SFAS No. 141(R) effective January 1, 2009. There has been no impact on our consolidated financial statements, as we have not entered into any business combinations in 2009.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51. SFAS No. 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. We adopted SFAS No. 160 effective January 1, 2009, with no impact on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, which amends and expands the interim and annual disclosure requirements of SFAS No. 133 to provide an enhanced understanding of an entity’s use of derivative instruments, how they are accounted for under SFAS No. 133 and their effect on the entity’s financial position, financial performance and cash flows. The provisions of SFAS No. 161 are effective as of January 1, 2009. We adopted SFAS No. 161 effective January 1, 2009, with no significant impact on our consolidated financial statements, other than additional disclosures which are included in Note H of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).”

In April 2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, Determination of the Useful Life of Intangible Assets (“FSP SFAS No. 142-3”). FSP SFAS No. 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”). The intent of FSP SFAS No. 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R and other applicable accounting literature. FSP SFAS No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date. We adopted FSP SFAS No. 142-3 effective January 1, 2009, with no significant impact on our consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (“GAAP”) in the United States of America. This statement became effective for us on November 15, 2008. The adoption of SFAS No. 162 did not have a significant impact on our consolidated financial statements.

In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, (“FSP EITF 03-6-1”) which provides that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share under the two class method. FSP EITF 03-6-1 was effective for us on January 1, 2009. There was no impact on our consolidated financial statements.

In April 2009, the FASB issued FSP SFAS No. 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies. This FSP amends and clarifies SFAS No. 141(R) to address application issues raised by preparers, auditors, and members of the legal profession on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This FSP is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We have not made any acquisitions during the first quarter of 2009, and as such, the adoption of this statement did not have a significant impact.

In April 2009, the FASB issued FSP SFAS No. 107-1 and APB Opinion No. 28-1, Interim Disclosures about Fair Value of Financial Instrument (“FSP SFAS No. 107-1”). This FSP amends FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods. This FSP is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. An entity may early adopt this FSP only if it also elects to early adopt FSP SFAS No. 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, (“FSP SFAS No. 157-4”) and FSP SFAS No. 115-2 and SFAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments. We did not elect early adoption. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this FSP requires comparative disclosures only for periods ending after initial adoption. We are currently evaluating the potential impact, if any, of FSP SFAS No. 107-1 on our financial statement disclosures.

In April 2009, the FASB issued FSP SFAS No. 157-4. This FSP:

	•		Affirms that the objective of fair value when the market for an asset is not active is the price that would be received to sell the asset in an orderly transaction.

	•		Clarifies and includes additional factors for determining whether there has been a significant decrease in market activity for an asset when the market for that asset is not active.

	•		Eliminates the proposed presumption that all transactions are distressed (not orderly) unless proven otherwise. The FSP instead requires an entity to base its conclusion about whether a transaction was not orderly on the weight of the evidence.

	•		Includes an example that provides additional explanation on estimating fair value when the market activity for an asset has declined significantly.

	•		Requires an entity to disclose a change in valuation technique (and the related inputs) resulting from the application of the FSP and to quantify its effects, if practicable.

	•		Applies to all fair value measurements when appropriate.

FSP SFAS No. 157-4 must be applied prospectively and retrospective application is not permitted. FSP SFAS No. 157-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. An entity early adopting FSP SFAS No. 157-4 must also early adopt FSP SFAS No. 115-2 and SFAS No. 124-2. We are not affected by FSP SFAS No. 115-2 and SFAS No. 124-2. We are currently evaluating the potential impact, if any, of FSP SFAS No. 157-4 on our financial statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2008.

We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at March 31, 2009, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

Hypothetical changes in interest rates and commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Credit risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies and refineries. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Although we have not generally required our counterparties to provide collateral to support their obligation to us, we may, if circumstances dictate, require collateral in the future. In this manner, we reduce credit risk.

Commodity price risk. We are exposed to market risk as the prices of oil and natural gas are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of oil and natural gas we have entered into, and may in the future enter into additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management activities could have the effect of reducing our revenues, net income and the value of our common stock. At March 31, 2009, the net unrealized asset on our commodity price risk management contracts was $133.8 million. An average increase in the commodity price of $5.00 per barrel of oil and $1.00 per Mcf for natural gas from the commodity prices at March 31, 2009, would have resulted in a decrease in the net unrealized asset on our commodity price risk management contracts, as reflected on our consolidated balance sheet at March 31, 2009, of approximately $29.2 million.

At March 31, 2009, we had (i) a oil price collar and oil price swaps that settle on a monthly basis covering future oil production from April 1, 2009 through December 31, 2012 and (ii) a natural gas price swap, natural gas price collars and natural gas basis swaps covering future natural gas production from April 1, 2009 to March 31, 2011, see Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information on the commodity derivative contracts. The average NYMEX oil futures price and average NYMEX natural gas futures prices for the three months ended March 31, 2009, was $43.18 per Bbl and $4.49 per MMBtu, respectively. At May 4, 2009, the NYMEX oil futures price and NYMEX natural gas futures price was $54.47 per Bbl and $3.73 per MMBtu, respectively. A decrease in oil and natural gas prices, should one continue during 2009, would increase the fair value asset of our commodity derivative contracts from their recorded balance at March 31, 2009. Changes in the recorded fair value of the undesignated commodity derivative contracts are marked to market through earnings as unrealized gains or losses. The potential increase in fair value asset would be recorded in earnings as unrealized gains. However, an increase in the average NYMEX oil and natural gas futures price above those at March 31, 2009 would result in an decrease in fair value asset and unrealized losses in earnings. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.

Interest rate risk. Our exposure to changes in interest rates relates primarily to long-term debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. To reduce our exposure to changes in interest rates we have entered into, and may in the future enter into additional interest rate risk management arrangements for a portion of our outstanding debt. The agreements that we have entered into generally have the effect of providing us with a fixed interest rate for a portion of our variable rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our credit facility, and the terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base.

At March 31, 2009, we had interest rate swaps on $300 million of notional principal that fixed the LIBOR interest rate (does not include the interest rate margins discussed above) at 1.90 percent for the three years beginning in May 2009. An average decrease in future interest rates of 25 basis points from the future rate at March 31, 2009, would have resulted in a decrease in the net unrealized asset on our interest rate risk management contracts, as reflected on our consolidated balance sheet at March 31, 2009, of approximately $2.1 million.

We had total indebtedness of $670.8 million outstanding under our credit facility at March 31, 2009. The impact of a 1 percent increase in interest rates on this amount of debt, assuming the interest rate swaps were outstanding, would result in increased annual interest expense of approximately $6.7 million and a corresponding decrease in net income before income tax.

The fair value of our derivative instruments is determined based on counterparties’ estimates and valuation models. We did not change our valuation method during 2009. During 2009, we were party to commodity derivative instruments. See Note I of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the three months ended March 31, 2009:


	Derivative Instruments Net Assets (Liabilities)^(a)
(in thousands)	Commodities			Interest Rate			Total

Fair value of contracts outstanding at December 31, 2008	$	173,523		$	(1,083	)	$	172,440
Changes in fair values ^(b)		(2,620	)		(2,426	)		(5,046	)
Contract maturities		(37,125	)		—			(37,125	)

Fair value of contracts outstanding at March 31, 2009	$	133,778		$	(3,509	)	$	130,269


(a)		Represents the fair values of open derivative contracts subject to market risk.

(b)		At inception, new derivative contracts entered into by us have no intrinsic value.

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. The Company’s management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Exchange Act, the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report. Based on that evaluation, the Company’s principal executive officer and principal financial officer concluded that the design and operation of the Company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Changes in internal control over financial reporting. There have been no changes in the Company’s internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the Company’s last fiscal quarter that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

We are party to the legal proceedings described under “Legal actions” in Note K of Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited).” We are also party to other proceedings and claims incidental to our business. While many of these other matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future results of operations.

Item 1A. Risk Factors

In addition to the other information set forth in this Report, you should carefully consider the risks discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, under the headings “Item 1. Business — Competition, Marketing Arrangements and Applicable Laws and Regulations,” “Item 1A. Risk Factors” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect the Company’s business, financial condition or future results. Except for the risk factor set forth below, there have been no material changes in the Company’s risk factors from those described in its Annual Report on Form 10-K for the year ended December 31, 2008.

Certain federal income tax deductions currently available with respect to oil and gas drilling and development may be eliminated as a result of future legislation.

On February 26, 2009, the White House released President Obama’s budget proposal for the fiscal year 2010. Among the changes contained in the budget proposal is the elimination of certain key United States federal income tax preferences currently available to oil and gas exploration and production companies. These changes include, but are not limited to (i) the elimination of the immediate expensing of intangible drilling costs and (ii) the repeal of the percentage depletion allowance for oil and gas properties.

On April 23, 2009, the Oil Industry Tax Break Repeal Act of 2009 was introduced in the Senate and includes many of the proposals outlined in the President’s budget proposal. It is unclear whether any such changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal, the senate bill or any other similar change in United States federal income tax law could represent an extremely significant reduction in the tax benefits that have historically applied to certain investments in oil and gas properties, which would adversely affect our financial condition and results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 6. Exhibits


Exhibit
Number		Exhibit
10.1		First Amendment to Amended and Restated Credit Agreement dated as of April 7, 2009, with the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on April 9, 2009, and incorporated herein by reference.)

10.2 (a)		Form of Restricted Stock Agreement (for executive officers).

31.1 (a)		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 (a)		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 (b)		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 (b)		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


(a)		Filed herewith.

(b)		Furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	CONCHO RESOURCES INC.
Date: May 8, 2009	By /s/ Timothy A. Leach
	Timothy A. Leach
	Director, Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)



	By /s/ Darin G. Holderness
	Darin G. Holderness
	Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)

EXHIBIT INDEX


Exhibit
Number		Exhibit
10.1		First Amendment to Amended and Restated Credit Agreement dated as of April 7, 2009, with the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on April 9, 2009, and incorporated herein by reference.)

10.2 (a)		Form of Restricted Stock Agreement (for executive officers).

31.1 (a)		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 (a)		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 (b)		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 (b)		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


(a)		Filed herewith.

(b)		Furnished herewith.